VIRGINIA ELECTRIC AND POWER COMPANY

RICHMOND, VIRGINIA 23261

April 29, 2010

U.S. Nuclear Regulatory CommissionAttention: Document Control DeskWashington, D.C. 20555

Serial No.NLOS/GDMDocket Nos.

License Nos.

10-266R2'50-28050-281DPR-32DPR-37

VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)SURRY POWER STATION UNITS 1 AND 2LICENSE AMENDMENT REQUESTMEASUREMENT UNCERTAINTY RECAPTURE POWER UPRATERESPONSE TO REQUEST FOR ADDITIONAL INFORMATION

By letter dated January 27, 2010 (Serial No. 09-223), Dominion submitted ameasurement uncertainty recapture (MUR) power uprate License Amendment Request(LAR) for Surry Power Station Units 1 and 2 to increase the rated power of each unit byapproximately 1.6%. On the same date, proprietary information [for the Cameronultrasonic flowmeter (UFM)] required to support the LAR was submitted under separatecover (Serial No. 09-223A). By letter dated February 4, 2010 (Serial No. 09-223B),Dominion provided additional supporting information to facilitate the NRC's review of theplant accident analyses updates required by and discussed in the MUR power uprateLAR.

In a letter dated April 14, 2010, the NRC provided a request for additional information(RAI) associated with the Dominion MUR power uprate LAR submittal. Dominion'sresponse to the NRC's RAI is contained in Attachment 1. As a result of the response tothe RAI questions, Dominion has identified an additional commitment to those includedin the list of regulatory commitments contained in Attachment 6 of the Surry MUR poweruprate LAR dated January 27,2010. The additional regulatory commitment is providedin Attachment 2. It should also be noted that the completion date for Commitment No.9, UFM commissioning and calibration will be completed, in Attachment 6 of the SurryMUR power uprate LAR has been changed from "April 2010" to "Prior to operatingabove 2546 MWt (98.4% RP)" to facilitate integration of this activity into the overall MURpower uprate license amendment implementation effort.

Serial No.1 0-266

Docket Nos. 50-280/281Page 2 of 3

If you have any questions or require additional information, please contactMr. Gary D. Miller at (804) 273-2771.

Sincerely,

COMMONWEALTH OF VIRGINIA

COUNTY OF HENRICO

)))

VICKI L. HULLNotary Public

Commonwealth of Virginia140642

My Commission expires May 31, 2010..............

The foregoing document was acknowledged before me, in and for the County andCommonwealth aforesaid, today by J. Alan Price, who is Vice President - Nuclear Engineering,of Virginia Electric and Power Company. He has affirmed before me that he is duly authorizedto execute and file the foregoing document in behalf of that Company, and that the statementsin the document are true to the best of his knowledge and belief.

Acknowledged before me this 297J'day of~r/L ,2010.

My Commission Expires:~ 3/, 2010 ff . ~ /) /tLiLh &( /i1dL

Notary Public

Attachments:

1. Response to NRC Request for Additional Information

2. Regulatory Commitment Associated with the Response to the NRC Request forAdditional Information

cc: U.S. Nuclear Regulatory CommissionRegion"245 Peachtree Center Avenue, NE Suite 1200Atlanta, Georgia 30303-1257

NRC Senior Resident InspectorSurry Power Station

State Health CommissionerVirginia Department of HealthJames Madison Building - 7th Floor109 Governor StreetSuite 730Richmond, Virginia 23219

Ms. K. R. CottonNRC Project ManagerU. S. Nuclear Regulatory CommissionOne White Flint NorthMail Stop 08 G-9A11555 Rockville PikeRockville, Maryland 20852-2738

Dr. V. SreenivasNRC Project ManagerU. S. Nuclear Regulatory CommissionOne White Flint NorthMail Stop 08 G-9A11555 Rockville PikeRockville, Maryland 20852-2738

Serial No.1 0-266

Docket Nos. 50-280/281Page 3 of 3

Serial No. 10-266

Docket Nos. 50-280,281

Attachment 1

RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION

MEASUREMENT UNCERTAINTY RECAPTURE POWER UPRATELICENSE AMENDMENT REQUEST

Virginia Electric and Power Company(Dominion)

Surry Power Station Units 1 and 2

Serial No.1 0-266Docket Nos. 50-280, 281

Attachment 1

Response to Request for Additional InformationMeasurement Uncertainty Recapture Power Uprate License Amendment Request

Surry Power Station Units 1 and 2

By letter dated January 27, 2010 (Serial No. 09-223), Virginia Electric and PowerCompany (Dominion) submitted a measurement uncertainty recapture (MUR) poweruprate License Amendment Request (LAR) for Surry Power Station (Surry) Units 1 and2 to increase the rated power of each unit by approximately 1.6%. In a letter dated April14, 2010, the NRC provided a request for additional information associated with theDominion MUR power uprate LAR submittal. Dominion's response to the NRC'srequest is provided below.

Vessels and Internals Integrity Branch

1. Attachment 5, Section IV, "Mechanical/Structural/Material Component Integrity andDesign," requires additional information. Table Matrix 1 of NRC RS-001, Revision 0,"Review Standard for Extended Power Uprates, " provides the NRC staff's basis forevaluating the potential for extended power uprates to induce aging effects onreactor vessel (RV) internals. Depending on the magnitude of the projected RVinternals f1uence, Table Matrix-1 may be applicable to the MUR application. In the"Notes" to Table Matrix-1, the NRC staff states that guidance on the neutronirradiation-related threshold for irradiation-assisted stress corrosion cracking (SCC)for pressurized water reactor (PWR) RV internal components are given in BAW­2248A, "Demonstration of the Management of Aging Effects for the Reactor VesselInternals," and WGAP-14577, Revision 1-A, "License Renewal Evaluation: AgingManagement for Reactor Internals." [T]he "Notes" to Table Matrix-1 state that forthermal and neutron embrittlement of cast austenitic stainless steel, SGC, and voidswelling, licensees will need to provide plant-specific degradation managementprograms or participate in industry programs to investigate degradation effects anddetermine appropriate management programs. Discuss your management of theabove-mentioned aging effects on RV internals in light of the guidance in BAW­2248A and WCAP-14577, Revision 1-A. Please also confirm whether you haveestablished an inspection plan to manage the age-related degradation in the SurryUnits 1 and 2 RV internals, or whether you have participated in the industry'sinitiatives on age-related degradation of PWR RV internals.

Dominion Response

Dominion confirms that it participates in industry initiatives on age-relateddegradation of PWR RV internals. Involvement has included participation on theEPRI Materials Reliability Program (MRP) committees that have researched therelevant degradation mechanisms, determined their importance to the functioning ofeach of the assemblies of the reactor internals, and produced the agingmanagement recommendations contained in MRP-227 Revision O. In support ofNRC acceptance of this document, Dominion is presently participating in the small

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group of MRP members that are responding to questions from NRC reviewers. InDominion letter No. 01-282, entitled "Virginia Electric and Power Company Surry andNorth Anna Power Stations Units 1 and 2 License Renewal Applications - Submittal"dated May 29, 2001, Dominion stated that inspections will be performed toimplement industry recommendations. Inspection plans are currently underdevelopment.

BAW-2248A is not applicable to Surry Units 1 and 2. WCAP-14577, Revision 1-A,"License Renewal Evaluation: Aging Management for Reactor Internals," was usedby Dominion for developing the Surry License Renewal Application. Within the Surrylicense renewal application, Table 3.1.3-W1, "WCAP-14577, Rev. 1-A, FSERResponse to Applicant Action Items", confirms the applicability of WCAP-14577, Rev1-A to Surry Units 1 and 2.

In the intervening years since issuance of WCAP-14577, further materials researchand functional requirements review carried out under EPRI sponsorship haveresulted in additional recommendations for aging management contained in MRP­227 Revision O. These recommendations are specifically configured for thecombinations of degradation mechanisms and component functional requirements ofthe reactor internals. The MRP document addresses the aging mechanisms that arelisted in WCAP-14577, including thermal and neutron embrittlement of castaustenitic stainless steel, SCC, and void swelling. It also has recommendationsspecific to plant design features. Therefore, in accordance with the commitment toconsider industry guidance, the "focused inspection" planned for Surry prior to theperiod of extended operation will be consistent with the augmented examinationsrequired by MRP-227 Revision O. In addition, the ASME Section XI examinationprogram for internals will continue to apply to other components not requiringaugmented examinations.

NRC RS-001 Revision 0, "Review Standard for Extended Power Uprates", isfocused on large power increases of up to 20%, as compared to the 1.6% MURpower uprate requested for Surry Units 1 and 2. In contrast, the Surry MUR resultsin very small changes to aging parameters such as temperature and neutron flux,and not at a level requiring revised aging management activities. Given the shortperiod of time between implementation of the uprate and the beginning of the periodof extended operation for each Surry reactor, the aging management program forthe reactor internals as currently committed for Surry Units 1 and 2 is adequate.Therefore, RS-001 does not apply to the Surry MUR.

Instrumentation and Controls Branch

1. License Amendment Request (LAR) Attachment 5, Page 20, Section 1.1. G("Completion Time and Technical Basis''), the LAR cites recent inspection of thefeedwater flow venturis at North Anna as evidence that venturi fouling is unlikely tooccur during any 48 hour period (during which the flow venturi may be used if the

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Attachment 1

unified fracture mechanics [sic] [ultrasonic flowmeter] UFM is declared non­functional). With the understanding that both plants are of similar vintage from thesame vendor, please provide information regarding the similarities between thefeedwater flow venturis installed in the North Anna and Surry units. Additionally,have the Surry unit feedwater flow venturi been similarly inspected? If so, howrecent was the inspection and were there any observations made regarding fouling?

Dominion Response

Surry has three feedwater venturis on each unit (1-FW-FE-1476, 1-FW-FE-1486,1-FW-FE-1496, 2-FW-FE-2476, 2-FW-FE-2486 and 2-FW-FE-2496). The feedwaterflow venturis at North Anna Power Station and Surry were manufactured by thesame vendor but with different sizes and model numbers. The Surry feedwaterventuris were replaced by Design Change 94-055 (Unit 1) in October 1995 andDesign Change 90-034 (Unit 2) in November 1991. Periodic inspections andcleanings have been performed on each of the venturis since that time inaccordance with the preventive maintenance program. The inspection and cleaningis performed by procedure 0-MPM-1 01 0-01, "Feedwater Venturi Inspection," andconsists of a check of the interior of the venturi, the high and low pressure taps, andan inspection for damage, corrosion, erosion or other abnormalities. This check isperformed by Maintenance and System Engineering personnel. The internals arethen cleaned. A quality inspection hold point is performed prior to system close outto check for foreign material. The cleaning procedure includes a caution to preservethe venturi integrity that reads "Venturi interior finish can be damaged from wirebrush by scratching. Care must be exercised during venturi cleaning to preventscratching venturi interior surface."

The following is a list of the years the venturis were inspected and the most recentpreventive maintenance work order history and the results found for each venturi:

Feedwater Flow Element Years Inspected

1-FW-FE-1476 1998,2000,2003,2006

1-FW-FE-1486 1998,2000,2003,2007

1-FW-FE-1496 1998,2000,2003,2009

2-FW-FE-2476 1995,1996,1999,2001,2005,2009

2-FW-FE-2486 1995,1996,1999,2001,2005,2009

2-FW-FE-2496 1995,1996,1999,2001,2005

• 1-FW-FE-1476 (U1 A Steam Generator (S/G) flow element) was last inspected inMay 2006. The as-found condition of the flow element was satisfactory. Slightpitting was noted at the 7 to 9 o'clock position, which was determined byEngineering to have no effect on venturi operation. This venturi is scheduled tobe inspected during the 2010 refueling outage.

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• 1-FW-FE-1486 (U1 B S/G flow element) was last inspected in October 2007.The as-found condition of the flow element was satisfactory. The internals werecleaned.

• 1-FW-FE-1496 (U1 C S/G flow element) was last inspected in April 2009. Theas-found condition of the flow element was excellent. There was no evidence ofcorrosion, erosion or other damage. The internals were cleaned and closeoutinspection was satisfactory.

• 2-FW-FE-2476 (U2 A S/G flow element) was last inspected in November 2009.The as-found condition of the flow element was satisfactory - no degradationwas found. High and low pressure lines were verified to be clear.

• 2-FW-FE-2486 (U2 B S/G flow element) was last inspected in November 2009.The as-found condition of the flow element was satisfactory.

• 2-FW-FE-2496 (U2 C S/G flow element) was last inspected in April 2005. Theas-found condition of the flow element was satisfactory. This flow element had ahigher buildup of magnetite (carbon-like coating on inside of pipe) than the othertwo flow elements for Unit 2 when inspected in 2005. The high side sensing lineport also had a buildup of magnetite. The coating was removed by cleaning. Noother discrepancies were noted. The next inspection of 2-FW-FE-2496 isscheduled for the 2011 refueling outage.

In addition to the periodic venturi inspections, Engineering performs monthlytrending of the feedwater flow for the three loops. There have been no adversetrends in the monthly flow data between inspections of the flow elements.Engineering also performs a comparison of the reactor power calorimetric toalternate power indications at 96% rated power during power escalation (e.g., aftereach refueling outage). This evaluation includes a review of the feedwater flowcalorimetric and steam flow calorimetric indicators. The difference between the mainfeedwater and the main steam power calorimetric has been stable, indicating nofouling or defouling of the feedwater venturis on Surry Units 1 and 2.

2. LAR Attachment 5, Page 20, Section 1.1.G ("Completion Time and Technical Bests"),the LAR states that a feedwater flow transmitter drift study was used as a basis fordetermining that transmitter drift over any 48-hour period would be negligible (duringwhich the flow venturi may be used if the UFM is declared non-functional). Pleaseprovide a reference for the cited study.

Dominion Response

The feedwater flow transmitter drift data was obtained from Surry InstrumentPeriodic Test (IPT) procedures (1-IPT-CC-FW-F-476, -477, -486, -487, -496 and

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Attachment 1

-497) that document the as-found and as-left transmitter output voltage during eachrefueling outage. The data from the six feedwater flow transmitters was reviewed fortwo consecutive 18-month operating cycles for Surry Unit 1 spanning from April2006 to April 2009. The as-left and as-found output voltages at the 100% powerdifferential pressure point were converted to mass flow rates, and the percentchange in main feedwater flow was calculated for each transmitter over the cycle.The cycle-average change in main feedwater flow was 0.017% and 0.014% for thefirst and second cycles, respectively, and the maximum individual transmitter outputchange was 0.05% flow. The transmitter drift analyses are documented in aninternal engineering document (Engineering Transmittal ET-NAF-09-0013) thatconforms to 10 CFR 50 Appendix 8 quality assurance requirements. The completedIPTs from April 2006, October 2007, and April 2009 are stored in the Surry recordssystem. Also, the applicable transmitter data sheets are attached to the EngineeringTransmittal. The evaluation using Unit 1 data was determined to be applicable forUnit 2 (both units have the same transmitter types). It was concluded that thefeedwater flow transmitter drift over any 48-hour period would be negligible for SurryUnits 1 and 2.

3. LAR Attachment 5, Page 22, Section I.1.H ("Actions for Exceeding Completion Timeand Technical Bests"), the LAR specifically notes that the Surry units have the optionto use either steam or feed flow as input to the calorimetric calculation when theUFM is non-functional. The LAR also notes that "within the first 48 hours after theidentification of a non-functional UFM, normalized main feed flow will be used."Section 3.3.5 of the Technical Requirements Manual indicates that in the first 48hours after the UFM is discovered non-functional, the normalized feedwater venturisystem would be used. Is there an intention, as part of this LAR, to be able to usethe main steam flow venturi for calorimetric calculations during the first 48 hoursfollowing UFM non-functionality to maintain power above 2,546 MWt? If so, is thesteam flow venturi measurement calibrated to the UFM?

Dominion Response

The main steam venturi-based calorimetric will not be used for power calorimetriccalculations to support plant operation above 2546 MWt. Technical RequirementsManual (TRM) 3.3.5 Required Action A.1 (provided in Attachment 4 of the SurryMUR power uprate LAR dated January 27,2010) allows use of only the NormalizedFeedwater Venturi System during the 48 hour completion time with a non-functionalUFM. The steam flow-based calorimetric may be used for operation ~ 2546 MWtconsistent with current plant procedures. TRM 3.3.5 Required Action 8.2 directs theuse of the Feed (not normalized) or Steam Venturi System after core power isreduced ~ 2546 MWt after the 48 hour completion time has passed.

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Reactor Systems Branch

1. Departure from Nucleate Boiling Ratio (DNBR) Analyses

The licensee evaluated the majority of these transients for the effect of the increasedpower level on DNBR. The evaluation included scaling the transient DNBRresponse by core power level and allocating a DNBR margin based on thecharacterization of the power uprate in terms of fractional effect on DNBR, asdetermined by the power evaluation. The evaluation did not consider other DNBR­significant parameters that could change as a result of the requested uprate,including rod surface heat flux, core/channel inlet enthalpy, core flow rate, andreactor coolant system temperature.

(a) Please explain the effect of the following parameters on the DNBR, and discusshow the DNBR margin evaluation accounted for each: (1) fuel rod surface heatflux; (2) core and channel inlet enthalpy; (3) core flow rate; and (4) reactorcoolant system temperature.

Dominion Response

The MUR power uprate evaluation considered the effects of the identified plantparameters on the calculation of departure from nucleate boiling ratio (DNBR). Thesummary of our evaluation is provided.

(1) An increase in the nominal fuel rod surface heat flux decreases the DNBR. Theeffect on the fuel rod surface heat flux increase is explicitly accounted for in theCOBRA statepoint analysis. The fuel rod surface heat flux is directly proportionalto total core power, and a 1.7% increase in core power produces a 1.7%increase in fuel rod surface heat flux in the COBRA analysis model. The 1.7%increase in heat flux produces the 3.3% decrease in DNBR. A 1.7% core powerand fuel rod surface heat flux increase was selected to bound the approximately1.61% MUR power uprate from 2546 MWt to 2587 MWt.

(2) An increase in the core inlet temperature decreases the DNBR. Core andchannel inlet enthalpy were not changed in the DNBR analysis for the MURuprate. This is conservative for the MUR uprate with constant reactor coolantsystem (RCS) average temperature (Tavg) of 573°F. As core power increaseswith constant Tavg, core and channel inlet temperature (enthalpy) decrease andprovide an increase in DNBR. This DNBR benefit was ignored for conservatismin the MUR power uprate assessment.

(3) An increase in the core mass flow rate increases the DNBR. Core mass flowrate was not changed in the DNBR analysis for the MUR uprate. The full-powerstatistical DNBR analyses assume the RCS is at the minimum measuredvolumetric flow (MMF) rate. The reduction in core inlet temperature discussedabove in part (2) at a constant MMF would increase the fluid density, increase

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Attachment 1

the core mass flow rate, and increase DNBR. This DNBR benefit was ignored forconservatism in our MUR power uprate assessment.

(4) The current full-power RCS Tavg is 573°F, and Surry plans to maintain the sameTavg at the MUR power level of 2587 MWt. As discussed above in parts (2) and(3), the MUR power uprate from 2546 MWt to 2587 MWt core power with aconstant RCS Tavg of 573°F will reduce core inlet enthalpy and increase thevessel mass flow. The DNBR benefits from these changes were ignored indetermining the 3.3% DNBR penalty.

Core power is the only plant parameter in the Updated Final Safety Analysis Report(UFSAR) Chapter 14 hot full power statistical DNBR analyses not bounded at MURpower uprate conditions. The DNBR margin evaluation conservatively assumes nobenefit attributed to the core and channel inlet enthalpy, core mass flow rate, andRCS temperature at MUR uprate conditions. The experience described below hasshown that a full reanalysis (transient response and DNBR) at a 1.7% MUR poweruprate produces a smaller DNBR increase than the 3.3% statepoint penalty that wasdeveloped for Surry. The reanalysis of the rod withdrawal at power (RWAP) eventfrom UFSAR Section 14.2.2 was performed to demonstrate adequate reactorprotection with the proposed change to the K3 pressure constant in theOvertemperature ~T (OT~T) reactor trip. The reanalysis is discussed in Section VIIIof Attachment 5 of the LAR dated January 27, 2010 [Reference 1a]. For a 1.7%increase in core power from 2546 MWt to 2589.3 MWt, the minimum DNBRdecreased by 2.4% from 1.68 to 1.64 (above the DNBR limit of 1.46). This analysisexplicitly accounted for the decrease in core inlet temperature and increase in coremass flow rate corresponding to RCS Tavg of 573°F at 2589.3 MWt core power(versus 2546 MWt in the analysis of record). With the exception of the RWAP eventwhich is specifically reanalyzed, the 3.3% DNBR penalty applied against full-powerstatistical DNBR events is conservative for the range of thermal-hydraulic conditionsexpected for accidents initiated from the MUR uprate power level of 2587 MWt(1.61% increase above 2546 MWt).

(b) Provide a detailed DNBR margin evaluation to substantiate the claim that there isadequate retained DNBR margin to account for the effect of the requested poweruprate.

Dominion Response

Thermal-hydraulic evaluations were reviewed for the three most recent cycles foreach Surry unit (six total cycles). Each calculation documents the DNBR penaltiesapplicable to the core reload, identifies the DNBR limits and retained DNBR margin,and demonstrates positive retained DNBR margin for each Surry UFSAR Chapter 14DNB event. This evaluation of cycle-specific DNBR margins is performed consistentwith Dominion's NRC-approved reload design methodology in VEP-FRD-42, Rev.2.1-A [Reference 1b]. DNBR penalties against retained margin are classified as 1)generic fuel design issues (e.g., fuel rod bow), 2) cycle-specific violations of limits

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(e.g., unbounded power shapes or peaking factors), or 3) plant operating conditions.The use of retained DNBR margin is consistent with Dominion's NRC-approvedStatistical DNBR Evaluation Methodology in VEP-NE-2-A [Reference 1c] and isdiscussed in Surry UFSAR Section 3.4.3.5 [Reference 1d]. The Reference 1band1c topical reports are identified as References 1 and 3a in Surry TechnicalSpecification 6.2.C, "Core Operating Limits Report" [Reference 1e]. Six cycles ofdesign data provide an adequate overview of trends in unbounded cycle-specificparameters to assess available DNBR margin for future MUR uprate cycles.

Table 1 summarizes the DNBR penalties that are expected during MUR upratecycles. The 13.0% retained DNBR margin is applicable to statistical DNB analysesof Surry Improved Fuel using the WRB-1 correlation (difference between safetyanalysis limit of 1.46 and statistical design limit of 1.27), as discussed in Section 11.2of Attachment 5 of the Surry MUR power uprate LAR dated January 27, 2010[Reference 1a]. A DNBR margin summary is provided for two groups of UFSARChapter 14 events: 1) accidents that are protected by the OT1.\T reactor trip; 2)accidents that credit other reactor protection (non-OT1.\T events). These events aretracked separately, because the cycle-specific power shape penalties are different.Table 1 shows adequate retained DNBR margin is available to accommodate the3.3% penalty for a bounding 1.7% power uprate.

Table 1: Typical Retained DNBR Margins for Full Power Statistical DNB Events

OT11T Events Non-OTI1T Events

Retained DNBR Margin 13.0% 13.0%

Generic Fuel Design Issues

Fuel Rod Bow 2.8% 2.8%

Cycle-Specific UnboundedParameters 0.8% 4.5%

Power Shapes*

Plant Operating Conditions

Bypass Flow 1.7% 1.7%

1.7% Power Uprate 3.3% 3.3%

Margin = Retained Margin - Penalties + 4.4% + 0.7%

* The maximum power shape penalty from SIX recent Surry cycles IS reported. Future cycles areexpected to produce smaller penalties due to a change in the core loading pattern strategy thatreduces the magnitude of unbounded cycle-specific power shapes.

References

1a. Letter from L. N. Hartz (Dominion) to USNRC, Virginia Electric and PowerCompany (Dominion), Surry Power Station Units 1 and 2, License AmendmentRequest, Measurement Uncertainty Recapture Power Uprate, Serial No. 09-

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Attachment 1

223, Rev. 1, January 27, 2010. [NRC ADAMS Accession NumberML100320264]

1b. Topical Report VEP-FRD-42, Revision 2.1-A, Reload Nuclear DesignMethodology, August 2003.

1c. Topical Report VEP-NE-2-A, Statistical DNBR Evaluation Methodology, June1987.

1d. Surry Updated Final Safety Analysis Report, Revision 41.

1e. Surry Power Station Units 1 and 2 Technical Specifications.

2. /tems Within the Reload Licensing Methodologv Scope

For the Excessive Heat Removal due to Feedwater System Malfunctions, theExcessive Load Increase, the Loss of Reactor Coolant Flow, and the Loss ofExternal Electrical Load transients, provide either explicit analyses, or the followinginformation outlined in RIS 2002-03, Attachment 1, Section 11/:

(a) Identify the accident/transient that is the subject of the analysis;

(b) Provide an explicit commitment to re-analyze the transient/accident, consistentwith the reload methodology, prior to implementation of the power uprate;

(c) Provide an explicit commitment to submit the analysis for NRC review, prior tooperation at the uprate power level, if NRC review is deemed necessary by thecriteria in Title 10 of the Code of Federal Regulations (10 CFR) 50.59; and

(d) Provide a reference to the NRC's approval of the plant's reload methodology.

Dominion Response

For the applicable UFSAR Chapter 14 events, Surry will re-analyze the transientconsistent with Dominion's NRC-approved reload design methodology in VEP-FRD­42, Rev. 2.1-A [Reference 2a] prior to implementation of the MUR power uprate.This topical report is identified as Reference 1 in Surry Technical Specification 6.2.C,"Core Operating Limits Report" [Reference 2b]. If NRC review is deemed necessarypursuant to the requirements of 10 CFR 50.59, the accident analyses will besubmitted to the NRC for review prior to operation at the uprate power level. Thesecommitments apply to the following Surry UFSAR Chapter 14 DNBR analyses thatwere analyzed at 2546 MWt consistent with the Statistical DNBR EvaluationMethodology in VEP-NE-2-A [Reference 2c]:

• Section 14.2.7 - Excessive Heat Removal due to Feedwater System Malfunctions(Full Power Feedwater Temperature Reduction case only);

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• Section 14.2.8 - Excessive Load Increase Incident;

• Section 14.2.9 - Loss of Reactor Coolant Flow; and

• Section 14.2.10 - Loss of External Electrical Load

The Surry UFSAR description for each Chapter 14 DNBR analysis will be modifiedto reflect the results of the MUR uprate analysis. The UFSAR updates will beperformed in accordance with Commitment #8 in Attachment 6 of the Surry MURpower uprate LAR dated January 27,2010 [Reference 2d].

References

2a. Topical Report VEP-FRD-42, Revision 2.1-A, "Reload Nuclear DesignMethodology," August 2003.

2b. Surry Power Station Units 1 and 2 Technical Specifications.

2c. Topical Report VEP-NE-2-A, "Statistical DNBR Evaluation Methodology," June1987.

2d. Letter from L. N. Hartz (Dominion) to USNRC, "Virginia Electric and PowerCompany (Dominion), Surry Power Station Units 1 and 2, License AmendmentRequest, Measurement Uncertainty Recapture Power Uprate," Serial No. 09­223, Rev. 1, January 27, 2010. [NRC ADAMS Accession NumberML100320264]

3. Steam Line Break

Evaluate the effects of the requested uprate against a hot full power main steam linebreak (MSLB) and demonstrate that the transient remains non-limiting.

Dominion Response

Section 14.3.2 of the Surry UFSAR [Reference 3a] describes the basis for why amain steam line break (MSLB) at power is bounded by the DNBR analysis at zeropower. Following a trip at power, the reactor coolant system (RCS) contains morestored energy than at no load, the average coolant temperature is higher than at noload, and there is appreciable stored energy in the fuel. The additional storedenergy is removed via the cooldown caused by the MSLB before no-load conditionsare reached. After the additional stored energy above no load is removed, thecooldown and reactivity insertions proceed in the same manner as in the analysisthat is initiated from hot zero power conditions. Since the initial SG liquid mass issignificantly larger at no load than at full power, the magnitude and duration of theRCS coo/down are less for a MSLB at power. For the MUR uprate, the increase incore thermal power would increase the core stored energy by a small amount, RCSaverage coolant temperature will be the same, and the steam generator pressureand liquid mass will not change significantly. Collectively, these small effects would

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produce essentially the same MSLB response at either 2546 MWt or 102% of 2546MWt core power.

The Surry UFSAR "at power" discussion is supported by generic MSLB analysesperformed by Westinghouse in WCAP-9226 [Reference 3b]. Analyses wereperformed for a 3-loop PWR similar to Surry at 0%, 30%, 70%, and 102% of 2785MWt core power. The maximum analyzed power level of 102% of 2785 MWt isbounding for Surry's current rated power of 2546 MWt and the MUR rated power of2587 MWt. WCAP-9226 demonstrates that, for a MSLB at core power levels greaterthan Surry's, the reactor protection system provides adequate protection to ensurethe DNB design basis is not violated prior to and immediately following a reactor trip.Furthermore, WCAP-9226 concludes that the limiting MSLB transient occurs from azero power initial condition. The Surry UFSAR analysis basis with zero power as thelimiting MSLB case was verified for the Surry core power uprate from 2441 MWt to2546 MWt (Section 3.4.1 in Attachment 3 of Reference 3c) and remains valid for theMUR power uprate to 2587 MWt.

Even though the MSLB is classified as an ANS Condition IV event, Surry continuesto meet the more stringent ANS Condition II DNBR limits for this event. Thisconclusion is reconfirmed for each reload in accordance with Section 3.3.4.4 oftopical report VEP-FRD-42, Rev. 2.1-A [Reference 3d].

References

3a. Surry Updated Final Safety Analysis Report, Revision 41.

3b. WCAP-9226, Revision 1, "Reactor Core Response to Excessive SecondarySteam Releases," Westinghouse Electric Corporation, January 1978.

3c. Letter from James P. D'Hanlon (Virginia Power) to USNRC, "Virginia Electricand Power Company, Surry Power Station Units 1 and 2, Proposed TechnicalSpecification Changes to Accommodate Core Upratinq," Serial No. 94-509,August 30, 1994.

3d. VEP-FRD-42, Revision 2.1-A, "Reload Nuclear Design Methodology," August2003.

4. Control Rod Assembly DroP/Misalignment

For the Control Rod Assembly Drop/Misalignment transient, clarify whether cycle­specific confirmation of the dropped rod limit lines will consider uprated operation,and whether the confirmation is performed in accordance with NRC-approved reloadlicensing methodology.

If the confirmation is not performed in accordance with NRC-approved reloadlicensing methodology, provide a disposition for the Control Rod AssemblyDrop/Misalignment transient that adheres to the guidance in Section 111.3 ofAttachment 1 to RIS 2002-03.

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Dominion Response

The Surry cycle-specific confirmation of the dropped rod limit lines will consider theMUR uprated core power of 2587 MWt. Because the dropped rod limit lines arebased on a core power of 2546 MWt with a DNBR safety analysis limit of 1.46, the3.3% DNBR penalty (for a bounding 1.7% power uprate) will be applied on a reloadbasis for the COBRA analysis of the Surry Improved Fuel for the dropped rod event.The 3.3% DNBR penalty is conservative for the thermal-hydraulic conditionsexpected during the dropped rod event initiated from the MUR power level of 2587MWt (1.61% increase above 2546 MWt). The cycle-specific confirmation of theSurry dropped rod limit lines is performed according to Section 3.3.4.2 in the NRC­approved topical report VEP-FRD-42, Revision 2.1-A [Reference 4a], which isidentified as Reference 1 in Surry Technical Specification 6.2.C, "Core OperatingLimits Report" [Reference 4b].

References

4a. VEP-FRD-42, Revision 2.1-A, "Reload Nuclear Design Methodology," August2003.

4b. Surry Power Station Units 1 and 2 Technical Specifications.

5. Licensing Basis Control

10 CFR 50.71(e) promulgates requirements for updating the final safety analysisreport (FSAR), stating, in part, that FSAR update submittals "shall contain all thechanges necessary to reflect information and analyses submitted to the Commissionby the applicant or licensee or prepared by the licensee pursuant to Commissionrequirement since the submittal of the original FSAR, or as appropriate, the lastupdate to the FSAR under this section. The submittal shall include ... all safetyanalyses and evaluations performed by the licensee either in support of approvedlicense amendments.... " In light of the statement, in selected notes to Table 11-2,that "The UFSAR analyses of record for DNBR do not need to be updated," explainhow adherence to 10 CFR 50.71 will be maintained following implementation of therequested MUR uprate.

Dominion Response

The statement in Table 11-2 was intended to differentiate between the approach ofusing retained DNBR margin in lieu of revising or updating the explicit DNBRtransient analysis that is presented in the UFSAR [Reference 5a]. The SurryUFSAR will be updated to identify the 3.3% DNBR penalty that is applied to eachfull-power statistical DNBR event that was analyzed at 2546 MWt core power. Thepenalty is applicable to COBRA analyses of the Surry Improved Fuel product. The

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following UFSAR sections will be modified:

• Section 14.2.4, Control Rod Assembly Drop/Misalignment

• Section 14.2.7, Excessive Heat Removal Due to Feedwater System Malfunction(Full Power Feedwater Temperature Reduction)

• Section 14.2.8, Excessive Load Increase Incident

• Section 14.2.9, Loss of Reactor Coolant Flow

• Section 14.2.10, Loss of External Electrical Load

As discussed in Section VIII of Attachment 5 of the Surry MUR power uprate LARdated January 27, 2010 [Reference 5b], the Rod Withdrawal at Power event inUFSAR Section 14.2.2 was reanalyzed at a bounding core power of 2589.3 MWt(1.7% above 2546 MWt) and the results of the re-analysis will be added to UFSARSection 14.2.2. The UFSAR updates described above will be performed inaccordance with Commitment #8 in Attachment 6 of the LAR dated January 27,2010 [Reference 5b].

References

5a. Surry Updated Final Safety Analysis Report, Revision 41.

5b. Letter from L. N. Hartz (Dominion) to USNRC, "Virginia Electric and PowerCompany (Dominion), Surry Power Station Units 1 and 2, License AmendmentRequest, Measurement Uncertainty Recapture Power Uprate," Serial No. 09­223, Rev. 1, January 27, 2010. [NRC ADAMS Accession NumberML100320264]

6. Transducer Replacement

In the submittal, the licensee states that they will generate transducer replacementprocedures. It is unclear when the procedures will be finalized, whether before, orafter implementation ofan MUR.

Dominion Response

The transducer replacement procedure (EFP-18) is provided in both the Installationand Commissioning Manual and the Maintenance and Troubleshooting Manual.Dominion will incorporate this vendor procedure into Surry station procedures priorto operating above 2546 MWt (98.4% RP). [See Surry MUR LAR, Serial No. 09­223, Attachment 6, Commitment 3, January 27,2010.]

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7. Software

Describe the system software verification and validation program. How does theprogram ensure data from the UFM is appropriately analyzed and applied?

Dominion Response

The Leading Edge Flowmeter (LEFM) Software Verification and Validation (V&V)Program is designed to document the specification, implementation and testing ofthe LEFM software so that the software responds and performs in an expected anddefined manner. The V&V Program is designed to meet EPRI TR-103291 S-V1-3.The program defines the requirements, guides the implementation, and confirmsproper implementation by test of the LEFM application software. The site specificsoftware inputs (lNI files) are measured and determined by the commissioningprocedure (EFP-61) and the procedure governing the creation and documentation ofthe INI file (EFP-302-2). These procedures are performed under Cameron's QAprogram so that the calculations are independently reviewed and the INI' file isentered into the revision control plan. The data is checked for consistency withlaboratory calibration testing and documented in the System Uncertainty Calculation.

8. Self-Verification Feature

Explain the self-verification feature of the software.

Dominion Response

The LEFM self-verification features provide a comprehensive check of signal quality,timing, path lengths, speed of sound, velocity profiles, and measurement statistics.The values are compared and traceable through the System Uncertainty Analysis toensure that the system remains within its design basis uncertainty. These features'are described in detail in the Topical Reports ER-80P and ER-157P and in the LEFMSpecification LEFM--J103 contained in the Verification and Validation ProgramDocumentation.

9. Definition

In the submittal, the licensee states that the software "continuously adjusts venturiflow coefficients and feedwater resistance temperature detector (RTD)temperatures." Define the term continuously.

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Dominion Response

The term continuously is defined as once per minute based on rolling, one houraverages. The software continuously calculates feedwater (FW) flow normalizationfactors and feedwater temperature and pressure biases to calculate FilteredNormalized FW Flow.

10.Preventive Maintenance Program

The licensee states that they will develop a preventive maintenance program. When. is the program scheduled to be developed?

Dominion Response

Guidelines and recommendations for Maintenance are contained in the LEFMMaintenance and Troubleshooting Manual. Dominion will incorporate theseguidelines and recommendations into Surry station procedures prior to operatingabove 2546 MWt (98.4% RP). [See Surry MUR LAR, Serial No. 09-223, Attachment6, Commitment 3, January 27,2010].

11. Calibration and Maintenance

Are calibration and maintenance procedures established? If not, when will theprocedures be finalized?

Dominion Response

The affected calibration and maintenance procedures are being revised as part ofthe MUR implementation design change packages (DCPs) (DCPs SU-08-0027 andSU-08-0028). These procedures are scheduled to be finalized prior to operatingabove 2546 MWt (98.4% RP). [See Surry MUR LAR, Serial No. 09-223, Attachment6, Commitment 3, January 27,2010].

12. Conditions Adverse to Quality

Define "adverse to quality" with respect to reporting deficiencies to the manufacturerand what actions are implemented if a condition "adverse to quality" is found to exist.

Dominion Response

Section 4, Terms and Definitions, of ASME NQA-1-1994, "Quality AssuranceRequirements for Nuclear Facility Applications," defines "condition adverse to

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quality" as "an all-inclusive term used in reference to any of the following: failures,malfunctions, deficiencies, defective items, and nonconformances. A significantcondition adverse to quality is one which, if uncorrected, could have a serious effecton safety or operability." The Dominion Quality Assurance Topical ReportDOM-QA-1 entitled, "Nuclear Facility Quality Assurance Program Description,"states, "The Company has established and implements corrective action programs,procedures, and processes to assure that conditions adverse to quality at Companynuclear facilities are promptly identified and corrected." Upon discovery of adeficiency or condition adverse to quality, Dominion procedures require entry of thecondition into the Central Reporting System, determination of the cause of thecondition, and performance of appropriate corrective actions. These actions mayinclude, but are not limited to, notification in accordance with 10 CFR 21, Reportingof Defects and Noncompliance.

13.Power Calorimetric

Please explain the differences when using steam flow in the power calorimetricrather than feed flow.

Dominion Response

The constituents of the current total calorimetric uncertainty are the uncertainties forthe flow venturi discharge coefficient, venturi differential pressure measurement,feedwater temperature measurement, moisture carryover, and steam pressuremeasurement. The current power calorimetric uncertainties at Surry Units 1 and 2are 0.90% rated power using main feedwater flow and 1.21% rated power usingmain steam flow. These calculations are based on input from the plant computersystem. Both methods provide a calorimetric uncertainty that is less than the 2%used in the deterministic safety analyses. As stated in the response toInstrumentation and Controls Branch Question #3, the main steam venturi-basedcalorimetric will not be used to support plant operation above 2546 MWt.

Accident Dose Branch

1. Section 11/.2.8.1.3 of Attachment 5 to the January 27, 2010, Surry MUR poweruprate LAR (Agencywide Documents Access and Management System (ADAMS)Accession No. ML100320264) provides information about the atmosphericdispersion factors (X/Q values) used in the steam generator tube rupture analysis.This section states that the control room (CR) and low population zone (LPZ) X/Qvalues remain unchanged from the current licensing basis and cites SurryAmendment No. 230 (ADAMS Accession No. ML020710159) dated March 8, 2002,as the reference. Table 11/.5 of Attachment 5 lists the CR X/Q values, which werealso used for the MSLB accident dose assessment.

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NRC staff agrees that the LPZ XlQ values listed in Table 11I-5 of the LAR are thosein the safety evaluation (SE) that supports Amendment No. 230, but was unable tofind the CR XlQ values in the SE. Therefore, please provide a reference for anddiscussion of the CR XlQ values, including confirmation that use of the CR XlQvalues for the MUR power uprate LAR remains unchanged from their use in thecurrent licensing basis analysis.

Dominion Response

Time dependent X/Q values for the Main Steam Line Break (MSLB) and SteamGenerator Tube Rupture (SGTR) control room emergency intake were originallydocketed as part of the Control Room Dose Calculations/Habitability Assessment(Reference 1c). The MSLB and SGTR control room X/Q values used in the currentdesign basis were docketed as part of the stretch power uprating (References 1aand 1b). A discussion of these values can be found in Sections 3.7.2.2.3 (MSLB)and 3.7.2.3.3 (SGTR) of Reference 1a. The MSLB and SGTR control room X/Qvalues are based on the Murphy and Campe methodology.

The emergency control room intake X/Q value (3.79E-03 sec/rrr') is a 0-8 hour X/Qvalue that was applied over the duration of the MSLB release and for the duration ofthe SGTR after the control room is isolated. The emergency control room intakeX/Q value is presented in Table 3.7.2.2-4 of Reference 1a. The normal control roomintake X/Q value (7.71E-03 sec/ rrr') is a 0-8 hour X/Q value that was applied to theSGTR prior to isolation by an SI signal, which occurs at 0.0687 hours (247 seconds).The normal control room intake X/Q value is presented in Section 3.7.2.3.3 ofReference 1a.

The control room X/Q values remain unchanged from the current license basisanalysis.

References

1a. Letter from J. P. O'Hanlon (Dominion) to U.S. Nuclear Regulatory Commission,"Surry Power Station Units 1 and 2, Proposed Technical Specification Changesto Accommodate Core Uprating," Serial No. 94-509, August 30, 1994.(Reference 111-2 in Attachment 5 of the Surry MUR LAR, Serial No. 09-223,January 27, 2010.)

1b. Letter from B. C. Buckley (NRC) to J. P. O'Hanlon (Dominion), "Surry Units 1and 2, Issuance of Amendments Re: Uprated Core Power, (Serial No. 94-509)(TAC Nos. M90364 and 90365)," Serial No. 95-405, August 3, 1995.(Reference 111-3 in Attachment 5 of the Surry MUR LAR, Serial No. 09-223,January 27,2010.)

1c. Letter Serial No. 89-381A, "Surry Power Station, Units 1 and 2, Control RoomDose Calculations/Habitability Assessment Proposed Operating LicenseAmendment," October 26, 1989. (Reference 111-7 in Attachment 5 of the SurryMUR LAR, Serial No. 09-223, January 27, 201Q.)

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Mechanical and Civil Engineering Branch

1. Section IV.1.A.iv in Attachment 5 of Reference 1 [of the LAR] states that operation atthe proposed MUR conditions will have an insignificant impact on the analyses andevaluations for the reactor coolant loop piping, primary equipment nozzles, primaryequipment supports, Class 1 auxiliary piping lines attached to the reactor looppiping, and the Class 1 auxiliary line branch nozzles attached to the reactor looppiping. However, the LAR request does not indicate whether these piping systemcomponents and supports are still bounded by the existing design basis analyses.Please verify whether the current analyses of record (AOR) remain bounding for theaforementioned reactor coolant piping components and supports. If the AOR is notbounding, wholly or in-part, please provide the updated analyses results for thereactor coolant piping components and supports which are not bounded under theproposed MUR uprate conditions.

Dominion Response

For the MUR power uprate conditions, the current analyses of record (AOR) remainbounding for the reactor coolant loop, primary equipment nozzles, primaryequipment supports, auxiliary piping lines attached to the reactor loop, and theauxiliary branch nozzles attached to the reactor loop piping. As identified in the LARsubmittal (Serial No. 09-223) dated January 27, 2010, ReS piping is designed toUSAS 831.1 code requirements.

2. Section IV.1.A.v in Attachment 5 of Reference 1 [of the LAR] indicates that theBalance-of-Plant (BOP) piping systems were reviewed to determine what impact theproposed MUR uprate conditions would have on the abilities of the various BOPpiping systems to continue operating at MUR power uprate levels. Accordingly,change factors based on thermal, pressure, and flow rate variances between thecurrent and proposed MUR power uprate levels were used to determine whether thecurrent AOR remains bounding for the BOP piping systems within the scope of theMUR power uprate LAR. Please address the following items regarding the BOPpiping acceptability:

(a) Please clarify the following statement from page 96 of Attachment 5 of Reference 1[of the LAR], 'The changes are acceptable." Please indicate whether acceptabilityrefers to all BOP piping system change factors remaining below 1.0; whether somesystems were above 1.0, but were found acceptable based on an updated analysisfor the system at the proposed MUR uprate conditions; or whether the current AORremains bounding for all BOP piping systems considered within the scope of thisLAR.

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Dominion Response

Changes in temperature and pressure, as a result of the proposed MUR poweruprate, were reviewed and determined to be insignificant for the BOP piping systemsexcept for the Main Steam and Steam Dump, Extraction Steam, Condensate,Feedwater, Heater Drain, and Service Water Systems. For these systems, thestresses were proportionally adjusted upward based on the change factors andcompared with the allowable values. The adjusted stresses are within applicableallowable values.

An increase in mass flow rate will usually affect stresses resulting from fluid transientevents such as pump trip, sudden valve closures, etc. A review was performed toidentify the BOP piping affected by an increase in mass flow rate. It was determinedthat only the Main Steam System piping between the steam generators and theturbine trip stop valves (TSVs), which are considered fast acting valves andtherefore capable of imposing significant fluid transient loadings in the system, wouldbe affected. An analysis of this piping was performed to qualify the piping for thisloading condition, since this loading condition had not been explicitly analyzedpreviously. The stresses were determined to be within the applicable allowablevalues.

Therefore, the changes in temperature, pressure and flow rate related to the MURpower uprate were determined to be acceptable.

(b) In concert with the response to part (a) above, please indicate which, if any, systemshad a change factor above 1.0 and indicate whether the thermal, pressure, or flowvariance was the limiting parameter for these systems.

Dominion Response

As identified in the response to part (a), the change factors for thermal and pressurevariance were calculated for the Main Steam and Steam Dump, Extraction Steam,Condensate, Feedwater, Heater Drain and Service Water Systems. Change factorsfor thermal variance for portions of the Main Steam and Steam Dump, ExtractionSteam, Condensate, Feedwater, Heater Drain and Service Water Systems werehigher than 1.0. Change factors for pressure variance for portions of the ExtractionSteam and Heater Drain Systems were also higher than 1.0. As noted in theresponse to part (a) above, only the Main Steam System piping required analysis forfluid transient loads, and the stresses due to fluid transient loads were determined tobe within allowable values.

(c) Based on the response to part (b) above, please summarize the results of theadditional evaluations performed for the affected systems and indicate whetherthese systems remain bounded by the current AOR.

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Dominion Response

The maximum change factors for the thermal and pressure variance for the MainSteam and Steam Dump, Extraction Steam, Condensate, Feedwater, Heater Drain,and Service Water Systems are tabulated below for Surry Units 1 and 2.

Unit 1 Unit 2

Temp Press Temp Press

Main Steam and Steam Dump System 1.031 ::;; 1 1.036 ::;; 1

Extraction Steam System 1.053 1.06 1.053 1.053

Condensate System 1.204 ::;; 1 1.191 ::;;1

Feedwater System 1.019 :s; 1 1.021 :s; 1

Heater Drain System 1.118 1.104 1.112 1.098

Service Water System 1.408 1 1.408 1

The maximum change factors for thermal variance for the Condensate, HeaterDrain, and Service Water Systems were 1.204, 1.118 and 1.408, respectively.However, the portions of these systems with these maximum change factors are lowtemperature sub-systems (less than or equal to 125.9°F), and the range oftemperature increase was approximately 10°F or less. The maximum change factorsfor thermal variance for the remaining systems were less than 1.07. These changesare not bounded by the current AOR, but were dispositioned as indicated in theresponse to part (d) below.

Change factors for pressure variance for the Extraction Steam and Heater DrainSystems were higher than 1.0. Specifically, the maximum change factors forpressure variance for portions of the Extraction Steam and Heater Drain Systemswere 1.06 and 1.104, respectively. These changes are not bounded by the currentAOR, but were dispositioned as indicated in the response to part (d) below.

(d) Based on the response to part (c) above, please provide the updated analysesresults for BOP piping systems whose current AOR is not bounding at the proposedMUR uprate conditions.

Dominion Response

Since the change factors were higher than 1.0 for portions of the Main Steam andSteam Dump, Extraction Steam, Condensate, Feedwater, Heater Drain, and ServiceWater Systems, the stresses in the affected subsystems were proportionallyadjusted upward based on the change factors. The prorated stresses weredetermined to be within allowable values.

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As noted in our response to part (a) above, an analysis was performed of theaffected Main Steam System piping to qualify the piping for the loading conditionassociated with an increase in mass flow rate. The stresses calculated in thisanalysis were determined to be within applicable allowable values.

Fire Protection Branch

1. The NRC staff notes that Attachment 5 to the LAR, Section 11.2.31, "Safe ShutdownFire Analysis (Appendix R Report) UFSAR 9.1," states that "... Operator actions inresponse to an Appendix R fire are not adversely impacted. The MUR power upratedoes not affect the worst case fire location or the post-fire local operations andcapability to complete repairs ... " The NRC staff requests the licensee to verify that(1) the MUR power uprate will not require any new operator actions; (2) any effectsfrom additional heat in the plant environment from the increased power will notprevent required post fire operator manual actions, as identified in the Surry fireprotection program, from being performed at and within their designated time; and(3) procedures and resources necessary for systems required to achieve andmaintain safe-shutdown will not change and are adequate for the MUR poweruprate.

Dominion Response

(1) Section VI1.1 in Attachment 5 of the Surry MUR power uprate LAR dated January27, 2010 summarizes the review of the operator actions assumed in the safetyanalyses, including the Appendix R fire safe shutdown analyses. The AppendixR fire safe shutdown analyses were reviewed thoroughly for the MUR poweruprate and the conclusions in Section VI1.1 apply: 1) existing operator actionsare not affected; 2) no reduction in operator action time was identified; 3) no newoperator actions were identified; and 4) no existing manual actions wereautomated.

(2) The effect on the plant environment from the increased core power wasevaluated, and it was concluded that the minor changes in temperature andpressure conditions will not prevent required post-fire operator manual actionsthat are identified in the Surry fire protection program from being performedwithin designated times.

(3) Procedures and resources necessary for systems required to achieve andmaintain safe-shutdown were reviewed and concluded to remain adequate forthe MUR power uprate.

2. The NRC staff notes that Attachment 5 to the LAR, Section VII.6.A.i, "Fire ProtectionSystems," states that "... The fire protection subsystems remain unchanged as aresult of the MUR power uprate... " However, this section does not discuss the

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changes in the physical plant configuration related to the fire protection program orchanges to the combustible loading at MUR power uprate conditions. Clarifywhether this request involves any changes in plant configurations related to the fireprotection program or changes to the combustible loading. If any, the staff requeststhe licensee to identify proposed changes and discuss the impact of these changeson the plant's compliance with the fire protection program licensing basis,10 CFR50.48, or applicable portions of 10 CFR 50, Appendix R.

Dominion Response

No changes to the installed fire protection systems are required as a result of theMUR mechanical and electrical installation design modifications.

The electrical portion of the installation will affect the combustible loading in criticalfire areas identified in Surry Technical Report EP-0012, "Combustible LoadingAnalysis," such as the Main Control Room and computer room where cables areinstalled in trays. This design change will add approximately 22.0 Ibs of combustiblematerial as a result of the addition of new cables to trays A30 and C30 in the MainControl Room and computer room area.

Cables are also being installed in the Cable Spreading Rooms, MechanicalEquipment Rooms and Turbine Building; however, they have no Appendix R impactsince they are either not in a Fire Area that is quantitatively tracked or are in an areathat has a qualitative analysis. The cables in these areas are being installed in steelconduit.

These modifications open and re-seal several existing penetrations and create newpenetrations in several Appendix R fire barriers. New penetrations are being addedfor the cables going to the UFM panel from the spool pieces. Several floorpenetrations from the Main Control Room are also being opened and re-sealed.Steel conduit is also being used.

The mechanical portion of the installations do not affect combustible loading. Thephysical requirements and response of the station fire protection systems remainunchanged.

The modifications implemented by these DCPs will not adversely impact theStation's design basis for compliance with Appendix R to 10 CFR 50. Themechanical installation will have a slight effect on one scenario assumed for theSurry B.5.b response, but the overall scenario and its goals are unchanged by thesemodifications.

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Electrical Branch

1. How does this increased loading affect the voltage drop through the servicetransformers and reserve station service transformers? Does it impact the DegradedVoltage Relay setting? How does this affect safety related loads when they start onthe safety busses during an accident? How does this impact the load managementdiscussed in the updated final safety analysis report (UFSAR) 8.4.1?

Dominion Response

Station Service bus voltages are maintained via the main generator voltage regulatorduring unit operation in accordance with station operating procedures. The ability tomaintain the specified bus voltages is not impacted. In addition, the Reserve StationService transformers automatic load tap changers will continue to maintain theirspecified voltage at downstream buses.

The increased loading of Station Service buses has minimal impact on theemergency buses. The increase in loading is due primarily to the Reactor CoolantPump induction motors. Changes to other large induction motors are small. Thevoltage profile calculation simulates two types of transients; unit trip or unit accident.For these events, the transfer of Station Service buses to .the Reserve StationService transformers is delayed approximately 30 seconds after a turbine trip. Foran accident scenario, the initial large motor starting load block is assumed to occurprior to the load transfer and is therefore unaffected. A calculation was performed todetermine the impact on the voltage profile. As expected, the emergency busvoltages are decreased after the delayed transfer due to the higher loading. Theresulting voltages are fully acceptable and do not approach the Degraded Voltagerelay settings. The Reserve Station Service transformer automatic load tapchangers will continue to correct voltage after the load transfer. No largechallenging motor starting load blocks occur after the load transfer. The DegradedVoltage relay settings are unaffected.

The voltage profile calculation performed to evaluate the impact of the Surry MURalso determined that the Reserve Station Service transformer loading remains wellbelow the transformer ratings. The existing load shedding schemes continue to limitloading adequately. The transformers are rated for 30 MVA and the maximumcalculated loading is 25.8 MVA. (The previous maximum was 24.3 MVA). TheStation Service bus loading is also within the Station Service transformer and busratings.

2. In Section V. 1.DJ of Attachment 5 of the LAR, the licensee states that transmissionsystem assessment included load flow studies of import/export system conditionsand single-contingency, both normal and stressed, system conditions. Was this gridanalysis performed for a dual unit trip after the increased loading of the poweruprate? Furthermore, under this uprated conditions, can a fault in a ReserveService transformer affect (trip) both units?

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Dominion Response

The Pennsylvania, New Jersey, Maryland Interconnection (PJM) grid analyses wereperformed per North American Electric Reliability Corporation (NERC) standards.N-1-1 assessments were performed as part of PJM's baseline assessments;however, re-dispatch is performed between each unit trip (e.g., in the model, trip Unit1, re-dispatch the system, trip Unit 2 and vice versa). A simultaneous trip of bothunits was not performed, since it is not required per NERC standards. Likewise, theSurry UFSAR does not require evaluation of a dual unit trip.

The uprate does not impact the consequences of a fault in a Reserve StationService transformer (RSST). During normal operation the Station Service buses aresupplied from the Station Service transformers. The normal loading of the ReserveStation Service transformers and emergency buses are not impacted by the uprate.The Reserve Station Service transformers are protected by high speed differentialprotective relays that will limit the duration of the fault. RSST-A supplies emergencybus 1J and RSST-8 supplies emergency bus 2H and RSST-C supplies emergencybuses 1Hand 2J. Accordingly, RSST-C has a higher probability of impacting bothunits since it supplies an emergency bus from both. The affected emergency busesare designed to separate from offsite power and align to the emergency dieselgenerators without tripping the unit(s).

3. In Section V.1.F.i of Attachment 5 of the LAR, the licensee states that at uprateconditions the main generator for Surry Unit 1 and 2 will be capable of exporting 500Mega Volt Ampere Reactive (MVAR) and importing approximately 430 MVAR. Alsoin Section V.1.D.i, the licensee states that Surry's generator output is limited to 400MVARs out or 200 MVARs in, due to the 4 kV station service buses. If gridconditions are stressed, such that the 4 kV bus voltage is not the limiting factor, willthe plant provide more reactive power to the grid (in excess of 400 MVARs)? If yes,was this factored in the stability analyses?

Dominion Response

No. Due to procedural limitations, Surry Unit 1 and 2 will not provide reactive powerin excess of 400 MVARs to the grid. Even though the generator is capable ofexporting 500 MVAR (lagging power factor of 0.865) and importing approximately430 MVAR (leading power factor of 0.899), Surry Unit 1 and 2 are only required byPJM, in our Interconnection Service Agreement, to operate at a power factor 0.95leading to 0.90 lagging. The existing station operating procedures limit MVAR to400 lagging and 200 leading, and main generator hydrogen pressure is currentlyoperated at a maximum of 60 psig. The higher MVAR capability described wouldonly be applicable after a turbine upgrade with implementation of changesnecessary to operate the main generator hydrogen pressure at 75 psig. Operating

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procedure changes have not been processed for these future modifications. Thecurrent procedures properly reflect existing main generator limits and not thepractical limits due to voltage constraints. The procedures permit operations staff touse the equipment for the full range of acceptable limits as long as other limits suchas voltage are not exceeded. Future procedure changes will reflect the equipmentlimits again permitting operations staff maximum operational flexibility.

Stability analyses are developed based on the equipment ratings, maximumoperating power (MW) limits, and applicable procedures associated with review andapproval of the proposed generation changes. The stability analyses performed bythe transmission provider are based on their internal guidance and NERCrequirements.

4. In section V.1.D.i of Attachment 5 of the LAR, the licensee states that the 941.7Mega Volt Ampere (MVA) main generators have been replaced with 1055 MVAgenerators and associated exciters and voltage regulators. Additionally, the licenseestates that the transmission system assessment did not require short circuit dutyscreening due to no changes in existing equipment. What affect does the maingenerators replacement have on the calculations performed for the grid analyses(short circuit duty screening)?

Dominion Response

The 1055 MVA main generators have been in service for several years and are partof the model for the transmission system used for the analyses including short circuitduty. The available short circuit current from the generators is based on thegenerator's impedances and not on the power output level. The impact of thegenerator upgrade was evaluated at the time the generators were replaced. TheMUR change has no impact on short circuit current.

5. In section IV.1.A.vii of Attachment 5 of the LAR, the licensee states that the newworst-case reactor coolant pump (RCP) motor loads are larger than the RCP motornameplate ratings. Furthermore, the licensee states that evaluations were conductedon the RCP motors to determine acceptability. Provide detailed discussion about theRCP motors worst-case loadings and the evaluation(s) performed to determine theiracceptability. What is the worst-case voltage drop on the safety busses when thelast RCP is started or operating at maximum load with grid at lowest allowablevalue? Discuss the affects of these conditions on the load management systemdescribed in UFSAR 8.4. 1.

Dominion Response

As described in a report provided by the Reactor Coolant Pump motor vendor, the

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Serial No.1 0-266Docket Nos. 50-280, 281

Attachment 1

temperature rises determined for the revised conditions for hot loop loading, coldloop loading, and for starting conditions still comply with the equipment specificationrequirements for the motors. Further, the changes to the thrust bearing loading forthe MUR uprate conditions were shown to be insignificant. Therefore, the RCPmotors are acceptable for operation at MUR power uprate conditions.

During unit startup, the Reactor Coolant Pump motors are supplied from theReserve Station Service transformers. Each motor is supplied from a differenttransformer. As startup progresses and motors are added, each Reserve StationService transformer will maintain voltage within the automatic load tap changersetpoint band regardless of loading on the other transformers. The starting currentfor the motors is based on the motor's impedance and not on the motor loading.Therefore, RCP motor starting voltages are unaffected by this change. Previouscalculations have shown that emergency bus voltage will drop below the DegradedVoltage relay setting during Reactor Coolant Pump motor starting (but not below theLoss of Voltage relay setting). The Degraded Voltage relay timer setting issufficiently long to permit motor starting and to permit the Reserve Station Servicetransformer automatic load tap changers to increase voltage after the motor start.The Degraded Voltage and Loss of Voltage relay settings permit RCP motor startingand are unaffected by the MUR change.

During unit startup, induction motor loading is gradually increased as loads arerequired. The Station Service buses are removed from the Reserve Station Servicetransformers at a low power level before bus loading is at the maximum level. Thus,Reserve Station Service loading during startup is not a concern.

The Station Service bus loading is within the Station Service transformer and busratings. The increased loading of Station Service buses has minimal impact on theemergency buses. The voltage profile calculation simulates two types of transients;unit trip or unit accident. For these events, the transfer of Station Service buses tothe Reserve Station Service transformers is delayed approximately 30 seconds aftera turbine trip. For an accident scenario, the initial large motor starting load block isassumed to occur prior to the load transfer and is therefore unaffected. A calculationwas performed to determine the impact on the voltage profiles. As expected, theemergency bus voltages are decreased after the delayed transfer due to the higherloading. The resulting voltages are fully acceptable and do not approach theDegraded Voltage relay settings. The Reserve Station Service transformerautomatic load tap changers will continue to correct voltage after the load transfer.No large, challenging, motor starting load blocks occur after the load transfer. TheDegraded Voltage relay settings are unaffected. The voltage profile calculationperformed to evaluate the impact of the Surry MUR also determined that theReserve Station Service transformer loading remains well below the transformerratings. The existing load shedding schemes continue to limit loading adequately.The transformers are rated for 30 MVA and the maximum calculated loading is 25.8MVA. (The previous maximum calculated loading was 24.3 MVA.)

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Serial No. 10-266Docket Nos. 50-280, 281

Attachment 2

REGULATORY COMMITMENT ASSOCIATED WITH THE RESPONSE TO THE NRCREQUEST FOR ADDITIONAL INFORMATION

MEASUREMENT UNCERTAINTY RECAPTURE POWER UPRATELICENSE AMENDMENT REQUEST

Virginia Electric and Power Company(Dominion)

Surry Power Station Units 1 and 2

Serial No.1 0-266Docket Nos. 50-280, 281

Attachment 2

REGULATORY COMMITMENT ASSOCIATED WITH THE RESPONSE TO THE NRCREQUEST FOR ADDITIONAL INFORMATION

The following list identifies only those actions committed to by SPS in this RAIresponse. Any other actions discussed in the submittal represent intended or plannedactions described for information only and are not considered regulatory commitments.

COMMITMENT SCHEDULED COMPLETION DATE(if required)

1. For the applicable UFSAR Chapter 14 events, Prior to operating aboveSurry will re-analyze the transient consistent 2546 MWt (98.4% RP).with Dominion's NRC-approved reload designmethodology in VEP-FRD-42, Rev. 2.1-A.

If NRC review is deemed necessary pursuantto the requirements of 10 CFR 50.59, theaccident analyses will be submitted to theNRC for review prior to operation at the upratepower level. These commitments apply to thefollowing Surry UFSAR Chapter 14 DNBRanalyses that were analyzed at 2546 MWtconsistent with the Statistical DNBREvaluation Methodology in VEP-NE-2-A:

• Section 14.2.7 - Excessive Heat Removaldue to Feedwater System Malfunctions (FullPower Feedwater Temperature Reductioncase only);

• Section 14.2.8 - Excessive Load IncreaseIncident;

• Section 14.2.9 - Loss of Reactor CoolantFlow; and

• Section 14.2.10 - Loss of External ElectricalLoad